Process for production of elemental iron

ABSTRACT

The invention is directed to a process to prepare elemental iron by contacting an iron ore feed with a reducing gas to obtain iron and an off-gas. The reducing gas is prepared by performing the following steps 
     (a) partially oxidizing a mixture comprising a sulphur containing solid carbonaceous fuel and gaseous CO 2  as carrier medium with oxygen, by supplying an oxygen containing gas and the solid carbonaceous fuel to a burner, thereby obtaining a gas comprising H 2 , CO, CO 2  and H 2 S;
 
(b) removing CO 2  and H 2 S from the gas obtained in step (a) to obtain the reducing gas comprising H 2  and CO and a first stream comprising CO 2  and H 2 S;
 
(c) reducing the content of H 2 S in the first stream comprising CO 2  and H 2 S obtained in step (b) in a liquid redox type process and
 
(d) recycling at least part of the CO 2  obtained in step (c) to step (a).

This patent application claims the benefit of European patentapplication No. 07121142.9, filed Nov. 20, 2007 and U.S. ProvisionalApplication 60/991,162, filed Nov. 29, 2007, both of which areincorporated herein by reference.

FIELD OF THE INVENTION

The invention is directed to a process to prepare elemental iron bycontacting an iron ore feed with a reducing gas comprising synthesisgas, wherein the reducing gas is prepared by a partial oxidationprocess.

BACKGROUND OF THE INVENTION

Direct reduction of iron (DRI) generates metallic iron in a solid formby removing oxygen from the iron ore by using a reduction gas that canbe provided from the synthesis gas obtained by gasification ofcarbonaceous feedstock. Industrially applied DRI processes includeMIDREX, HyL and FINMET, as described in “Development of ReductionProcess for the Steel Production” by M. Gojic and S. Kozuh, Kem. Ind. 55(1) 1-10 (2006).

EP-A-0916739 describes a process wherein the reducing gas for the DRIprocess is obtained by gasification of a coal slurry. The reducing gasfed to the DRI includes a recycle gas stream that has exited the DRI,and wherein acid gases have been removed from the recycle gas stream.

U.S. Pat. No. 5,871,560 describes a process wherein synthesis gas ismixed with an off-gas produced in a DRI process to be used as areduction gas and wherein H₂S is fed to the reducing gas.

U.S. Pat. No. 2,740,706, as filed in 1951, describes a process forreducing metal oxides by contacting with a reducing gas. In its examplesthe reducing gas is prepared by partial oxidation of natural gas inadmixture with carbon dioxide to obtain a reducing gas having two tothree times as much volume of carbon monoxide for each volume ofhydrogen. The reason, according to this publication, to add carbondioxide to the natural gas is to achieve such high contents of carbonmonoxide. Coal is mentioned as a possible feedstock instead of naturalgas. In this process sulphur is removed from the reducing gas bycontacting the gas with sponge iron.

The so-called entrained-flow gasification process for coal as describedin “Gasification” by C. Higman and M. van der Burgt, 2003, ElsevierScience, Chapter 5.3, pages 109-128 was developed after 1970 (see page 5of this reference).

It would be an advancement in the art to provide a process that has ahigher efficiency than the above-described processes.

SUMMARY OF THE INVENTION

The above is achieved by the following process. Process to prepareelemental iron by contacting an iron ore feed with a reducing gas toobtain iron and an off-gas, wherein the reducing gas is prepared byperforming the following steps

(a) partially oxidizing a mixture comprising a sulphur containing solidcarbonaceous fuel and gaseous CO₂ as carrier medium with oxygen, bysupplying an oxygen containing gas and the solid carbonaceous fuel to aburner, thereby obtaining a gas comprising H₂, CO, CO₂ and H₂S;(b) removing CO₂ and H₂S from the gas obtained in step (a) to obtain thereducing gas comprising H₂ and CO and a first stream comprising CO₂ andH₂S;(c) reducing the content of H₂S in the first stream comprising CO₂ andH₂S obtained in step (b) in a liquid redox type process and(d) recycling at least part of the CO₂ obtained in step (c) to step (a).

Applicants found that by recycling part of the CO₂ to step (a) a moreefficient process is obtained. A further advantage of the presentinvention is that, for a given amount of carbonaceous fuel to bepartially oxidised in the gasification reactor, a smaller reactor volumecan be used, resulting in lower equipment expenses, as compared to asituation wherein no CO₂ is present in step (a). A further advantage isthat the removal of CO₂ and H₂S is performed in one step, namely step(b), while in the process of U.S. Pat. No. 2,740,706 this removal takesplace in two steps. The separation of H₂S from the first streamcomprising CO₂ and H₂S by means of a liquid redox process is much moreefficient than removing H₂S from the entire effluent of step (a) as inthe process of U.S. Pat. No. 2,740,706.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 schematically shows a process scheme for a process according tothe present invention.

DETAILED DESCRIPTION

In the DRI process an iron ore feed is contacted with the reducing gascomprising H₂ and CO to obtain elemental iron and an off-gas. ExemplaryDRI processes are those mentioned earlier.

In a typical DRI process the iron ore feed is usually in the form ofpellets or in the lump form or a combination of the two. The iron ore issupplied to a heated furnace or to a set of reactors through which itdescends by gravity at superatmospheric pressure, e.g., 1.5-12 bar. Ironore feed is reduced in the said furnace or set of reactors by the actionof counterflowing reducing gas that has high H₂ and CO contents. Processspecifics of the DRI processes are described for example in “Kirk-OthmerEncyclopedia of Chemical Technology”, fourth edition, volume 14, JohnWiley & Sons, 1985, pages 855-872.

The reducing gas is used to remove oxygen from the iron oxide comprisedwithin the iron ore feed. The reducing process can be illustrated by thefollowing reaction, where H₂O and CO₂ are obtained as by-products:

Fe₂O₃+H₂→2Fe+3H₂O

Fe₂O₃+CO→2Fe+CO₂

Preferably the reducing gas has H₂/CO ratio of at least 0.5. It is alsopreferred that the reducing gas has a “gas quality” of at least 10. Thegas quality is defined as a ratio of reductants to oxidants, asdemonstrated by the following equation:

Gas quality=(mol % H₂+mol % CO)/(mol % H₂O+mol % CO₂)

Iron obtained from the DRI process is cooled and carbonized by means ofthe counterflowing gasses in the lower portion of a shaft furnaceaccording to the following reaction:

3Fe+CO+H₂→Fe₃C+H₂O

3Fe+CH₄→Fe₃C+2H₂

By means of this process it is possible to manufacture for exampleso-called cold DRI products, hot briquetted iron, or hot directreduction iron.

The off-gas obtained by the DRI process is the spent reducing gasexiting the furnace. The off-gas can be cleaned by scrubbing and CO₂removal and is preferably recycled to be used as the reducing gas.Preferably the off-gas is treated before the re-use as reducing gas tosatisfy the requirement for reducing gas as described above.

In step (a) of the process according to the invention a mixturecomprising a sulphur containing solid carbonaceous fuel and CO₂ withoxygen containing gas is partially oxidized, thereby obtaining a gascomprising H₂, CO, CO₂ and H₂S.

The partial oxidation may be performed by any process known. Preferablythe partial oxidation is performed by means of the so-calledentrained-flow gasification process as described in “Gasification” by C.Higman and M. van der Burgt, 2003, Elsevier Science, Chapter 5.3, pages109-128. More preferably step (a) is performed in an entrained-flowgasifier process wherein the reaction between the mixture ofcarbonaceous fuel and CO₂ with oxygen containing gas takes place in agasification reactor provided with one or more burners. In such aprocess an oxygen containing gas and a solid carbonaceous fuel aresupplied to a burner. CO₂ is used as carrier medium to transport thefuel to the burner. One or more burners can be provided in thegasification reactor. The burner can be a single burner directeddownward at the top of a vertically elongated reactor. Preferably thegasification reactor will have substantially horizontal firing burnersin diametrically opposing positions. The burner is preferably aco-annular burner with a passage for an oxygen containing gas and apassage for the fuel and the carrier gas. Partial oxidation of thecarbonaceous fuel occurs at a relatively high temperature in the rangeof 1000° C. to 2000° C. and at a pressure in a range of from about 1-70bar. Preferably the pressure is between 10 and 70 bar, more preferablybetween 30 and 60 bar. The gas is cooled with either direct quenchingwith water, direct quenching with the off-gas, direct quenching with thepart of the gas obtained in either steps (a) or (b), by indirect heatexchange against evaporating water or combination of such cooling steps.Slag and other molten solids are suitably discharged from thegasification reactor at the lower end of the said reactor.

The term solid carbonaceous fuel may be any carbonaceous fuel in solidform. Examples of solid carbonaceous fuels are coal, coke from coal,petroleum coke, soot, biomass and particulate solids derived from oilshale, tar sands and pitch. Preferably the solid carbonaceous fuel ischosen from the group of coal, petroleum coke, peat and solid biomass.Coal is particularly preferred, and may be of any type and sulphurcontent, including lignite, sub-bituminous, bituminous and anthracite.Although in many DRI processes natural gas is used as a fuel, coal is aninteresting choice for a fuel source because of its abundance. Coal ispreferably supplied to the burner in form of fine particulates. The termfine particulates is intended to include at least pulverizedparticulates having a particle size distribution so that at least about90% by weight of the material is less than 90 μm and moisture content istypically between 2 and 12% by weight, and preferably less than about8%, more preferably less than 5% by weight. Preferably coal is suppliedin admixture with CO₂ as a carrier medium.

Gaseous CO₂ containing carrier medium contains preferably at least 80%,more preferably at least 95% CO₂. CO₂ can be separated from the reducinggas and from the off-gas of the DRI process. It has been found that byusing CO₂ as obtained in step (c) in step (a), as the carrier medium, amore efficient process is obtained.

Preferably, the CO₂ containing carrier gas supplied in step (a) issupplied to the burner at a velocity of less than 20 m/s, preferablyfrom 5 to 15 m/s, more preferably from 7 to 12 m/s. Further it ispreferred that the CO₂ and the carbonaceous fuel are supplied at adensity of from 300 to 600 kg/m³, preferably from 350 to 500 kg/m³, morepreferably from 375 to 475 kg/m³.

In a preferred embodiment of the process according to the presentinvention, the weight ratio of CO₂ to the carbonaceous fuel in step (a)is in the range from 0.12-0.49, preferably below 0.40, more preferablybelow 0.30, even more preferably below 0.20 and most preferably between0.12-0.20 on a dry basis.

It has been found according to the present invention that using therelatively low weight ratio of CO₂ to the carbonaceous fuel in step (a)less oxygen is consumed during gasification.

In a preferred embodiment step a) comprises partially oxidizing amixture consisting of a sulphur containing solid carbonaceous fuel andCO₂ with oxygen containing gas.

The oxygen containing gas comprises substantially pure O₂ or air.Preferably it contains at least 90% by volume oxygen, with nitrogen,carbon dioxide and argon being permissible as impurities. Substantiallypure oxygen is preferred, such as prepared by an air separation unit(ASU). Steam may be present in the oxygen containing gas as supplied tothe burner to act as moderator gas. The ratio between oxygen and steamis preferably from 0 to 0.3 parts by volume of steam per part by volumeof oxygen. When the downstream DRI process requires a high CO to H₂ratio it is advantageous to use CO₂ instead of steam as a moderator gas.This CO₂ is preferably CO₂ as obtained in step (c). A mixture of thefuel and oxygen from the oxygen containing stream is then reacted in areaction zone in the gasification reactor.

The gaseous stream obtained in step (a) comprises mainly H₂ and CO,which are the main components of the synthesis gas, and can furthercomprise other components such as CO₂, H₂S, HCN and COS. The gaseousstream obtained in step (a) suitably comprises from 1 to 10 mol % CO₂,preferably from 4.5 to 7.5 mol % CO₂ on a dry basis when performing theprocess according to the present invention.

The gaseous stream obtained in step (a) is preferably subjected to a drysolids removal and wet scrubbing.

The dry solids removal unit may be of any type, including the cyclonetype. The dry solid material is discharged from the dry solids removalunit to be further processed prior to disposal.

In order to remove the particulate matter, for example soot particles,the gaseous stream obtained in step (a) is contacted with a scrubbingliquid in a soot scrubber. The gaseous stream exiting the gasifier isgenerally at elevated temperature and at elevated pressure. To avoidadditional cooling and/or depressurising steps, the scrubbing step inthe soot scrubber is preferably performed at elevated temperature and/orat elevated pressure. Preferably, the temperature at which the reducinggas is contacted with scrubbing liquid is in the range of from 120 to160° C., more preferably from 130 to 150° C. Preferably, the pressure atwhich the gaseous stream obtained in step (a) is contacted withscrubbing liquid is in the range of from 20 to 80 bara, more preferablyfrom 20 to 60 bara.

The process further comprises step (b) of removing CO₂ and H₂S from thegas obtained in step (a) thereby obtaining the reducing gas comprisingH₂ and CO and a first stream comprising CO₂ and H₂S.

Removing CO₂ and H₂S is performed in a, hereafter referred to, CO₂recovery system. The CO₂ recovery system is preferably a combinedCO₂/H₂S removal system. Preferably CO₂/H₂S removal is performed byabsorption using so-called physical and/or chemical solvent process. TheCO₂ recovery is performed on the gaseous stream obtained in step (a).The off-gas of the DRI contacting process is suitably also subjected tothe same or a different CO₂ recovery system to obtain a recycle reducinggas comprising CO and H₂ and a second stream comprising CO₂ and possiblyH₂S. In case the CO₂ recovery system is the same, the second stream andthe first stream are the same and will be referred to as the firststream.

It is preferred to remove at least 80 vol %, preferably at least 90 vol%, more preferably at least 95 vol % and at most 99.5 vol %, of the CO₂present in the gaseous stream obtained in step (a).

Absorption processes are characterized by washing the synthesis gas witha liquid solvent, which selectively removes the acid components (mainlyCO₂ and H₂S) from the gas. The laden solvent is regenerated, releasingthe acid components and recirculated to the absorber. The washing orabsorption process takes place in a column, which is usually fitted withfor example packing or trays. On an industrial scale there are chieflytwo categories of absorbent solvents, depending on the mechanism toabsorb the acidic components: chemical solvents and physical solvents.Reference is made to the absorption process as described in chapters8.2.1 and 8.2.2 of “Gasification” (already referred to), page 298-309,and Perry, Chemical Engineerings' Handbook, Chapter 14, Gas Absorption.

Chemical solvents which have proved to be industrially useful areprimary, secondary and/or tertiary alkanolamines. The most frequentlyused amines are derived from ethanolamine, especially monoethanol amine(MEA), diethanolamine (DEA), triethanolamine (TEA), diisopropanolamine(DIPA) and methyldiethanolamine (MDEA).

Physical solvents which have proved to be industrially suitable arecyclo-tetramethylenesulfone and its derivatives, aliphatic acid amides,N-methylpyrrolidone, N-alkylated pyrrolidones and the correspondingpiperidones, methanol, ethanol and mixtures of dialkylethers ofpolyethylene glycols.

A well-known commercial process uses an aqueous mixture of a chemicalsolvent, especially DIPA and/or MDEA, and a physical solvent, especiallycyclotetramethylene-sulfone also referred to as sulfolane. Such systemsshow good absorption capacity and good selectivity against moderateinvestment costs and operational costs. They perform very well at highpressures, especially between 20 and 90 bara.

Preferably the solvent comprises one or more compounds selected from thegroup of N-methylpyrrolidone (NMP), dimethyl ether of polyethyleneglycol (DMPEG), methanol or an amine such as di-isopropanol amine (DIPA)or mixtures of amines with sulfolane. More preferably, the solventcomprises an amine and sulfolane.

Preferably step (b) comprises one or more further removal systems thatmay be guard or scrubbing units, either as back-up or support to theCO₂/H₂S removal system. These further removal systems are aimed atremoving HCN and COS or other contaminants such as NH₃, H₂S, metals,carbonyls, hydrides or other trace contaminants which may be comprisedin the gas obtained in step (a).

Preferably step (b) is performed by at least two steps wherein in afirst step the gas obtained in step (a) is contacted with the HCN/COShydrolysis catalyst to convert HCN to NH₃ and COS to H₂S, followed byremoval of water and ammonia from the gas by cooling and/or scrubbing,and in a second step the gas obtained in said first step is contactedwith a suitable solvent, which is selective for absorbing CO₂ and H₂S asdescribed above.

The process of contacting the gas obtained in step (a) with the HCN/COShydrolysis catalyst to convert HCN to NH₃ and COS to H₂S takes place bycatalytic hydrolysis in the hydrolysis unit. Examples of a suitablehydrolysis step are disclosed in WO-A-04105922. The hydrolysis zone canbe a gas/solid contactor, preferably a fixed bed reactor. Catalysts forthe hydrolysis of HCN and COS are known to those skilled in the art andinclude for example TiO₂-based catalysts or catalysts based on aluminaand/or chromium-oxide. Preferred catalysts are TiO₂-based catalysts.

The process further comprises step (c) of reducing the content of H₂S inthe first stream comprising CO₂ and H₂S obtained in step (b). Preferablythe CO₂ as obtained in step (c) has a sulphur content lower than 10ppmv, more preferably between 5 and 10 ppmv. Step (c) is performed bymeans of a liquid redox type process. More preferably step (c) isperformed by liquid redox type process by contacting the stream of CO₂and H₂S obtained in step (b) with an aqueous reactant solutioncomprising iron (III) chelate of an organic acid or complex reactantsystem to produce elemental sulphur which is recovered as a by-productof the present process either prior to or subsequent to regeneration ofthe reactant, as described in for example “Gas Purification” by A. Kohland R. Nielsen, Gulf Publishing Company, fifth edition, pages 670-840,and more specifically pages 803-840.

The reduction of H₂S content in step (c) can also be performed on amixture of the first and second stream comprising CO₂ and H₂S.

The process according to the invention further includes step (d) whereinat least part of the CO₂ obtained in step (c) is recycled to step (a).The CO₂ that is recycled to step (a) is isolated from the first andoptional second stream comprising CO₂ and H₂S.

The reducing gas obtained in step (b) is directed to an expander whereinthe pressure of the reducing gas is reduced and power is generated. Thereducing gas is then heated in a gas heater before entering the furnaceof the DRI process where it is contacted with iron ore feed to produceiron and the off-gas.

The off-gas of the DRI contacting process can be subjected to the CO₂recovery as described above, thereby obtaining a recycle reducing gascomprising CO and H₂ and a second stream comprising CO₂ and H₂S. Therecycle reducing gas comprising CO and H₂ can be recycled to the furnaceof the DRI process. The CO₂ from the first and second streams comprisingCO₂ and H₂S is preferably used in step (a) as a carrier medium to carrythe coal to the burner. Excess CO₂ is preferably stored in subsurfacereservoirs or more preferably a part of the CO₂ as obtained in step (c)is used for one of the processes comprising enhanced oil recovery, CO₂sequestration or coal bed methane extraction. A part of the CO₂ can beinjected into the subterranean zone to obtain a desired pressure in saidsubterranean zone such to enhance the recovery of a hydrocarboncontaining stream as produced from said subterranean zone. A part of thereducing gas obtained in step (c) is preferably used as a fuel in a gasturbine to generate power.

In the process scheme of FIG. 1 a sulphur containing solid carbonaceousfuel (1), preferably coal as fine particulates, is mixed with the CO₂containing carrier gas (2) and fed to a burner of a gasification reactor(4) where it is contacted with an oxygen containing gas (3) to obtainthe reducing gas comprising H₂ and CO (5) and slag (4 a). The reducinggas (5) is treated in a dry solids removal unit (6). The dry solidmaterial is discharged from the dry-solids removal unit (6) via line (6a). Stream (7), free of solids, enters a CO₂/H₂S removal system (8)where the removal of acid gases such as CO₂, H₂S, and any othercontaminants as HCN, COS takes place. After exiting the CO₂/H₂S removalsystem (8), the cleaned reducing gas (13) is expanded in an expander(14) whereby power (15) is produced to be used in the current process orin a separate process. The reducing gas exiting the expander via line(16) is further heated in a heater (17) and is directed as a stream (18)to a DRI furnace (19) where it is used as a reducing gas to be contactedwith the iron ore (20). The resulting iron is discharged via stream(21). The off-gas (22) of the DRI furnace (19) is directed to a CO₂removal system (23) wherein CO₂ is separated thereby obtaining a secondstream comprising CO₂ and H₂S (24) and a recycle reducing gas comprisingCO and H₂ (35). The recycle reducing gas comprising CO and H₂ (35) isrecycled to the DRI furnace (19) via heater (17), by combining stream(35) with stream (16). In case the sulphur content of the second streamcomprising CO₂ and H₂S (24) is more than 10 ppmv, the said stream (24)is directed as stream (25) to a liquid redox process type unit (10)where it joins the first stream comprising CO₂ and H₂S (9) exiting theCO₂/H₂S removal system (8). Gas treatment can take place in separatesystems (8) and (23), or it can take place in a single system. Thesulphur obtained in the liquid redox process type unit (10) isdischarged via stream (11) while the CO₂ exits the liquid redox processtype unit (10) as stream (29). A part (30) of stream (29) can bedirected to any other suitable process where CO₂ is used via the stream(32). Another part of the stream (29) is used as carrier gas (2) forcarrying the carbonaceous feed (1) to the gasifier (4). In case thatsulphur content of the stream (24) is less than 10 ppmv, the gas stream(24) may by-pass the liquid redox process type unit (10) as stream (31).This stream may also find use as the above stream (32) or as carrier gas(2).

1. A process to prepare elemental iron by contacting an iron ore feedwith a reducing gas to obtain iron and an off-gas, wherein the reducinggas is prepared by performing the following steps (a) partiallyoxidizing a mixture comprising a sulphur containing solid carbonaceousfuel and gaseous CO₂ as carrier medium with oxygen, by supplying anoxygen containing gas and the solid carbonaceous fuel to a burner,thereby obtaining a gas comprising H₂, CO, CO₂ and H₂S; (b) removing CO₂and H₂S from the gas obtained in step (a) to obtain the reducing gascomprising H₂ and CO and a first stream comprising CO₂ and H₂S; (c)reducing the content of H₂S in the first stream comprising CO₂ and H₂Sobtained in step (b) in a liquid redox type process and (d) recycling atleast part of the CO₂ obtained in step (c) to step (a).
 2. The processaccording to claim 1, wherein the off-gas comprises CO₂ and H₂S, andwherein CO₂ and H₂S are removed from the off-gas to obtain a recyclereducing gas comprising CO and H₂ and a second stream comprising CO₂ andH₂S, and wherein the recycle reducing gas is used as reducing gas, andwherein the first and second stream comprising CO₂ and H₂S are mixed anda mixture of the first and second stream comprising CO₂ and H₂S issubjected to step (c).
 3. The process according to claim 1, wherein theweight ratio of CO₂ to the carbonaceous fuel in step (a) is less than0.5 on a dry basis.
 4. The process according to claim 1, wherein thesulfur containing solid carbonaceous fuel is chosen from the groupconsisting of coal, petroleum coke, peat and solid biomass.
 5. Theprocess according to claim 1, wherein the gas obtained in step (a) alsocomprises HCN and COS and wherein step (b) is performed by (i)contacting the gas as obtained in step (a) with a HCN/COS hydrolysiscatalyst to convert HCN to NH₃ and COS to H₂S, followed by removal ofwater and ammonia from the gas by cooling and/or scrubbing; (ii)contacting the gas obtained in step (i) with a solvent, which isselective for absorbing CO₂ and H₂S.
 6. The process according to claim5, wherein the solvent comprises one or more compounds selected from thegroup consisting of N-methylpyrrolidone (NMP), dimethyl ether ofpolyethylene glycol (DMPEG), methanol, an amine and mixtures of amineswith sulfolane.
 7. The process according to claim 6, wherein the solventcomprises di-isopropanol amine (DIPA)
 8. The process according to claim6 wherein the solvent comprises an amine and sulfolane.
 9. The processaccording to claim 1, wherein step (c) is performed by liquid redox typeprocess by contacting the stream of CO₂ and H₂S obtained in step (b)with an aqueous reactant solution comprising an iron (III) chelate of anorganic acid or complex reactant system to produce elemental sulphurwhich is recovered as a by-product of the process either prior to orsubsequent to regeneration of the reactant.
 10. The process according toclaim 1, wherein a part of the CO₂ as obtained in step (c) is used forenhanced oil recovery, CO₂ sequestration or coal bed methane extraction.11. The process according to claim 1, wherein a part of the CO₂ asobtained in step (c) is injected into a subterranean zone to obtain adesired pressure in the subterranean zone to enhance the recovery of ahydrocarbon containing stream as produced from the subterranean zone.12. The process according to claim 1, wherein part of the reducing gasobtained in step (b) is used as a fuel in a gas turbine to generatepower.